1. Field of the Invention
The present invention relates in general to the field of hydraulic fracturing, monitoring, and data transmission of microseismic information from a zone of interest within a reservoir, and more particularly, to the utilization and employment of electrically and physically isolated downhole acoustic monitoring equipment within a fracturing treatment well to detect microseismic events during fracturing operations.
2. Description of the Related Art
Hydraulic fracturing has been used for over 60 years in more than one million wells to improve the productivity of a hydrocarbon bearing formation, particularly those drilled in low permeability reservoirs. An estimated 90% of the natural gas wells in the United States alone use hydraulic fracturing to produce gas at economic rates. Successful hydraulic fracturing is generally considered vital for economic production of natural gas from shale beds and other ‘tight gas’ plays.
Fracturing treatment operations are typically employed in vertical, deviated, and horizontal wells. In a typical well development operation, the wellbore of the treatment well is drilled through the desired formation where the fracture treatment will take place.
The hydraulic fracture is formed by pumping a fluid into the wellbore at a rate sufficient to increase the pressure downhole to a value in excess of the fracture gradient of the formation rock in the area of interest. The pressure causes the formation to crack, allowing the fracturing fluid to enter and extend the crack further into the formation. One method to keep this fracture open after the injection stops is to add a solid proppant to the fracture fluid. The proppant, which is commonly sieved round sand or other nonporous material, is carried into the fracture. This sand is chosen to be higher in permeability than the surrounding formation, and the propped hydraulic fracture then becomes a high permeability conduit through which the formation fluids can flow to the well.
Determining the size and orientation of completed hydraulic fractures is quite difficult and expensive, and in less expensive alternatives, highly inaccurate. It is well known that hydraulic fractures create a series of small “earthquakes” that can be mapped to show the position of the fracture event. The technology currently in use deploys a series of microseismic detectors typically in the form of geophones inside a separate monitoring well to measure fracturing events while pumping a hydraulic fracture treatment. Deployment of geophones or tilt meters on the surface can also be used, but the resolution is significantly less as you go deeper in the well.
Tiltmeter arrays, deployed on the surface or in a nearby monitoring well, measure the horizontal gradient of the vertical displacement. Microseismic detector arrays, deployed in a nearby monitoring well or on the surface adjacent the zone of interest if it is not too deep and/or environmental noise is not too excessive, can detect individual microseismic events associated with discrete fracture opening events. The microseismic event can be located in three dimensions by a triangulation methodology based on comparing acoustic arrival times at various sensors in a receiver array. By mapping the location of small seismic events that are associated with the growing hydraulic fracture during the fracturing process, the approximate geometry of the fracture can be inferred.
Although the use of a monitoring well located separate from the treatment well is often preferred as it provides improved accuracy, particularly in areas with high environmental noise and/or relatively inaccessible surface conditions, the cost of drilling a monitor well is typically in the area of $10 million and requires 30-50 days of drilling rig time. Further, availability of surface real estate or other factors can prevent the monitoring well from being drilled sufficiently close to the area of interest, and thus, results in a degraded performance.
In order to try to reduce capital costs and deployment time, some progressive operators have, with minimal success, attempted to build a combination monitoring and treatment well by placing the acoustical sensors in the annulus of the treatment well. Some other operators, have instead chosen to deploy the acoustic sensors directly in the treatment flow path.
Recognized by the inventors, however, is that as a result of the pumping of the fracturing fluid, such acoustic sensors located along the annulus of the treatment well or within the flow path encounter substantial noise during the hydraulic fracturing events, which in turn, results in the collection of acoustic data having an excessively low signal-to-noise ratio. Accordingly, also recognized by the inventors is that this type of monitoring can generally only provide usable data when the fracture is closing, and thus, causes the operator to miss the fracturing events occurring while pumping the fracturing slurry.
Further recognized by the inventors is that due to the exposure limitations of the electrical data/power conduit (e.g., run with the acoustic sensors to transmit data to the surface), the operator is limited to certain slurry concentrations and is limited by the amount of total pressure that can be applied while fracturing due to the pressure limitation of the electric line cable heads. Still further, recognized by the inventors is that the deployment of acoustic sensors within the treatment flow or in the annulus adjacent current or potential future sidetracking operations can impede such operations.
Recognized, therefore, by the inventors is that there is a need for systems and processes that requires only a single treatment well to reduce capital costs and deployment time, that includes provisions for isolating the acoustic sensors to provide for gathering during pumping of the fracturing slurry downhole, acoustic data having an acceptable signal-to-noise ratio. Also recognized by the inventors is that there is a need for systems and processes that allow for high slurry concentrations and that allow for a total pressure necessary for optimal fracturing without concern for the pressure limitations of electric conduit/line cable heads in the communication pathway of the acoustic sensors, and/or that does not impede current or future sidetracking operations.